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Results
Study On Existence of Asphaltene Deposition In Deepwater Crude Oil Pipeline
Chen, Junwen (Southwest Petroleum University) | Zhu, Hongjun (Southwest Petroleum University) | Jing, Jiaqiang (Southwest Petroleum University) | Li, Qingping (CNOOC, Research Center) | Yao, Haiyuan (CNOOC, Research Center) | Yue, Xinxin (Petroleum Exploration and Development Research Institute)
ABSTRACT As the development of investigation on the deepwater oil-gas resources, it has become a controversial issue whether asphaltene deposition exists in deepwater oil pipelines. Based on the related researches, this paper studies on the main factors such as temperature, pressure and oil composition, causing asphaltene deposition, and theoretically infers the possibility of asphaltene deposition in deepwater oil pipelines; meanwhile, the subsequent deposition in pipelines is analyzed. The results indicate that it's entirely possible for the considered deepwater pipeline system to meet the conditions of asphaltene deposition which is hardly controlled by fluid's own flow. INTRODUCTION Deepwater oilfields have become the leading potential regions among the newly developed oil and gas reservoirs all over the world, the development and utilization of the deepwater oil-gas resources are considered as an important strategy to implement the sustainable economic development and ensure the energy security by many countries. Malfunction occurs anywhere in the submarine oil pipeline can cause paralysis of the whole system due to its closed pipeline system. The asphaltene deposition in the wellbore has greatly influenced the oil production of onshore oilfield and will endanger the safe operation if it occurs in the submarine pipeline. Therefore, the existence of asphaltene deposition in the submarine pipeline system should be proved before any effective measure can be taken to prevent the damage by asphaltene deposition so as to ensure the normal operation of the submarine pipeline system.
- Europe (1.00)
- Asia > China (0.95)
- North America > United States > Texas (0.47)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud (0.28)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Mata Acema Field (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019 > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > King Lear Area > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Greece > Prinos Field (0.99)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Study On Phase Inversion Characteristics of Heavy Oil Emulsions
Duan, Linlin (Southwest Petroleum University) | Jing, Jiaqiang (Southwest Petroleum University) | Wang, Jinzhu (Southwest Petroleum University) | Huang, Xiaofeng (Institute of Oil Extraction Engineering, CNOOC) | Qin, Xiaoguang (Southwest Petroleum University) | Qiu, Yijie (Southwest Petroleum University)
ABSTRACT Rheological properties of different heavy oils and their emulsions were measured using RheolabQC rheometer, and their phase inversion were observed using XP-300C microscopic image system. The viscosity of water in oil emulsions constantly increases as the content of bound water rises, and suddenly decreases while it increases to a certain extent, which is corresponding to its phase inversion point, a condition parameter that can be effectively lowered with a suitable chemical and enhanced by high-rate and/or long time stirring. The increase of inner phase concentration can promote the oil-water interface rupture and eventually make the inner and outer phases inversed. INTRODUCTION There are various challenges in heavy oil production and transportation, and one of the most important challenges is the formation of water in oil (W/O) emulsions. Actually, oil-water mixtures are easily to form W/O emulsions due to high-speed shearing of pumps or other mechanical devices along their transportation pipeline and natural surfactants like asphaltene and others existing in the oils. The viscosity of a W/O emulsion is generally higher than that of crude oil at the same test conditions, which results in a high pressure drop along the pipeline, and it is also difficult to separate water from the emulsion. According to this, various methods have been proposed to reduce the viscosities of emulsions (Lin et al., 2008; Kuldip et al., 1998). The viscosity of a W/O emulsion can be significantly reduced by adding some appropriate emulsifiers, and its inner and outer phases can be inversed to form an O/W emulsion with lower bound water content. Pilehvari (1988) et al. investigated the rheological characteristics of heavy oil emulsions and pointed out that all W/O emulsions show a remarkable shear thinning and oil droplet size is the main factor affecting their rheological behaviors.
- Asia > China (1.00)
- Asia > India (0.69)
- North America > United States (0.68)
- Asia > India > Gujarat > Cambay Basin > North Cambay Basin (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
Numerical Calculation of Cathodic Protection Potential Distribution For Ocean Construction
Liu, Fuguo (College of civil engineering of Tianjin university, Tianjin, China, China Offshore Oil Engineering Co.,ltd, Technology Research Dept. CNOOC Research) | Wu, Suru (Chemicals, minerals & metallic materials inspection center of TianJin Eentry-Exit Inspection and Quarantine Bureau)
ABSTRACT Using FEM during the design of cathodic protection system can optimize the cathodic protection system and forecast the distribution of potential in real marine environment. A single bar was modeled for which protection was provided by an anode located in different places. Through analysis of each unit and synthesis in the whole area, mathematical model of 3-D finite element was constructed. Potential distributions were calculated. The performance predictions are strongly dependent on anode placement. INTRODUCTION Cathodic protection (CP) as a rehabilitation method has proven to stop corrosion in real marine environment. CP extends the service life of buried steel pipelines, oil and gas well casings, offshore oil-drilling structures, seagoing ship hulls, marine piles, water tanks and chemical equipment. The concept behind CP consists of shifting the electrode potential of a metal to a more negative value where the corrosion rate is sufficiently low to suppress the anodic reaction (Morgan, 1959): (equation 1 shown in paper) and the cathodic reaction is enhanced: (equation 2,3 shown in paper). thus decreasing the overall corrosion current. Oxygen reduction (Eq. 2) is the main cathodic reaction in concrete, because concrete has a high pH and oxygen is thermodynamically a far more powerful electron acceptor than the hydrogen ion (Eq.(3)). The direct current (DC) for CP systems can be supplied either via mains power in impressed current CP systems (ICCP) or by a sacrificial anode CP system (SACP). In a SACP device, single or multiple anodes distribute the cathodic current to the protected structure. For buried structures the anodes are often inert graphite. For immersed seawater structures they may be highsilicon cast iron or platinum-coated titanium. Magnesium, zinc, aluminium, and aluminium-zinc-indium alloy sacrificial anodes, welded to buried andimmersed structures, provide long-term CP(Montoya, Aperador and Bastidas, 2009).
Influence of Cathodic Protection Potential On Corrosion of Carbon Steel In Seamud Containing Sulfatereducing Bacteria
Zhao, Xiaodong (School of Electromechanical Engineering, Zhejiang Ocean University, Institute of Oceanology, Chinese Academy of Sciences) | Yang, Jie (School of Electromechanical Engineering, Zhejiang Ocean University) | Fan, Xiqiu (School of Electromechanical Engineering, Zhejiang Ocean University) | Duan, Jizhou (Institute of Oceanology, Chinese Academy of Sciences)
ABSTRACT The reliability of cathodic protection(CP) on carbon steel buried in seamud containing Sulfate-reducing bacteria(SRB) was evaluated with emphasis on electrochemical impedance spectra(EIS) at different CP potentials. The relationship among CP potential, corrosion rate and bacteria activity was summarized by EIS results, weight-loss test and bacterial counts by most probability number(MPN) method, which showed that the steel at potential of −950 mV (CSE) was relatively well protected, with a stable and low corrosion rate. Bacterial counts showed that the growth activity and stability of SRB were lower at more negative CP potentials. −950 mV or even more negative potential was needed to ensure of efficient protection. INTRODUCTION As the most efficient method of corrosion protection, cathodic protection(CP) technique has been recognized worldwide(NACE Standard, 1969). It is widely used as an anticorrosion technique for the protection of steel structures in marine environment. To achieve the basic protection, the protection potential of −850mV (CSE) is essential. Extensive research has been carried out on microbiologically influenced corrosion (MIC). Microorganisms such as iron bacteria (IB), sulfate-reducing bacteria (SRB), iron-oxidizing bacteria (IOB), sulfuroxidizing bacteria (SOB) are mainly responsible for the corrosion underground. Kajiyama et al(1999) studied the CP reliability of buried pipeline in the sandy soil and sticky sludge containing IOB and SRB. Jung-Gu Kim et al(2001) discussed the CP standards for the buried pipeline with a coating layer of insulation, involving the influence of temperature on the cathodic protection potential. Baorong HOU et al(1993) studied the optimal anti-corrosion potential by AC impedance. Guezennec J et al(1991, 1994a, 1994b) investigated the relationship between CP potential and SRB-induced corrosion in marine sediments by AC impedance technique. Massimo S et al(1998) discussed the corrosion behavior of buried pipeline under CP through EIS study. Research with regard to the polarization effect on MIC is relatively little.
- Geology > Mineral > Sulfate (0.56)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.54)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.70)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT In this study, an artificial methane hydrate sediment sample is experimentally made based on a two-dimensional vessel with 320mm×320mm in cross section and 28mm in height. a sequence of experiments on MH dissociation behaviors by addition of ethylene glycol (EG) aqueous solution under varying concentration and injection flux and as well different production mode (Single-well or Multi-mode) are carried out. Special pressure behavior at the early stage of injection is attributable to the high MH saturation after completion of the formation. It suggests that higher solution concentration and the injection rate can facilitate cumulative gas production. However, gas production cannot sufficiently benefit from inhibitor injection with higher concentration as far as the input energy is concerned according to the energy-efficiency analysis. Multi-well mode shows its superiority over Single-well mode in terms of total gas production and Productivity as well. The variations of temperature field with the time elapsing reflected directly the advancement of hydrate dissociation front. It is difficult to produce all the MH in a reservoir simply with thermodynamic inhibitor injection because it gets harder for inhibitor solution to reach to remaining hydrate effectively. INTRODUCTION Natural gas hydrates are crystalline compounds that can contain a large amount of natural gas (Sloan, 1998). NGH are treated as a potential energy resource for the 21st century because a large amount of methane gas is trapped in hydrate reservoirs both onshore buried under the permafrost and offshore buried under the oceanic and deep lake sediments (Makogon, 1981; Okuda, 1993; Gornitz and Fung, 1994; Kvenvolden K, 2000; Collett, T. S, 2002; Kerr, R. A, 2004).The success coring of gas hydrate in South China Sea in 2007 confirms the existence of hydrate in Shenhu sea area. Therefore, developing methods for commercial production of natural gas from hydrate reservoirs is attracting considerable attention.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.83)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.71)
Determination of Critical Factors Affecting On Hydrogen Induced Cracking And Type I Sulfide Stress Cracking of High Strength Linepipe Steel
Kim, Wan Keun (Graduate Institute of Ferrous Technology, Pohang University of Science and Technology) | Park, Gyutae (Graduate Institute of Ferrous Technology, Pohang University of Science and Technology) | Kim, Kyoo Young (Graduate Institute of Ferrous Technology, Pohang University of Science and Technology) | Koh, Seong Ung (POSCO Technical Research Center) | Jung, Hwan Gyo (POSCO Technical Research Center)
ABSTRACT The metallurgical factors affecting HIC and SOHIC of high strength linepipe steel are investigated and the cracking resistance is correlated with diffusible hydrogen. Internal cracks were initiated at elongated MnS and TiNb(C, N) cluster regardless of the cracking mode. Increase in diffusible hydrogen content by cathodic charging or applying the external load makes the steel more susceptible to the cracking and it can imply that both of critical factors, inclusion clusters as well as diffusible hydrogen in the steel, should be carefully controlled to improve the cracking resistance. INTRODUCTION For the safe operation of pipeline in the wet H2S (hydrogen sulfide) condition, it should satisfy high corrosion cracking resistance. (NACE MR0175, 2002) Cracking phenomena has been classified into HIC (hydrogen induced cracking) and SSC (sulfide stress cracking) according to the presence of external loading. Also, SSC has two different cracking modes, SOHIC (stress-oriented HIC or type I SSC) and type II SSC and particularly, SOHIC has been of primary concern in the application of HSLA (high strength low alloy) steel which is preferred material in the oil and gas industry because of its cost effectiveness. Metallurgical key factors affecting HIC and SOHIC have been well introduced and many cracking mechanisms have been proposed. (Takahashi and Ogawa, 1995) Nevertheless, the relationship between HIC and SOHIC is still not clearly understood and it makes the application of HIC resistant steel to SSC condition difficult. (Pargeter, 2007) Even if HIC resistant steel has been believed to have high resistance to SOHIC because of its similar cracking characteristics, the uncertainty of relationship has been also reported. Cayard et al. indicated (2002) that HIC resistant steel may be more susceptible to SOHIC compared with the conventional HSLA steels and Pargeter reported (2007) about the uncertainty of relationship between HIC and SOHIC in his review paper.
- Asia (0.70)
- North America > United States (0.16)
Simulation of Hydrate Formation And Inhibition In Submarine Wet-gas Pipeline
Huang, Min (Southwest Petroleum University) | Jing, Jiaqiang (Southwest Petroleum University) | Zhang, Yi (CNOOC China Limited-Shanghai) | Yang, Xue (Loadmaster Universal Rigs Inc.) | Tang, Min (Offshore Oil Engineering Co. Ltd.) | Pu, Ming (PetroChina Planning & Engineering Institute)
ABSTRACT This study discusses hydrate formation conditions and the influences of CH4, N2, CO2 and condensate oil C6+ on hydrate formation conditions of three kinds of wet-gases from an offshore area in China using HYSYS software. The hydrate formation times of an experimental gas were measured by means of a static simulation experiment under different pressures. A table of methanol and glycol dosages for their hydrate control under different commissioning flow rates, pressures, inlet and outlet temperatures was established by using relevant theories and methods. Thus, a safe commissioning proposal of the production and submarine transportation of the gases has been presented. INTRODUCTION Natural gas is highly valuable around the world due to its great significance among the variety of resources, environment and global climate changes. Research on natural gas hydrate in oil and gas pipelines mainly involves flow assurance, safety, energy exploitation, seabed geologic hazards, gas storage and transportation, etc (Sloaned, 2003). Natural gas hydrate in oil and gas pipelines may block not only the pipeline but also the separation facilities and instruments, thus causing pressure and flow monitoring errors, reducing natural gas transportation volume, increasing pipeline pressure differences, and even damaging the pipe fittings and so on. It is a key unsettled technical problem in gas safe transportation to how to predict and prevent the formation of gas hydrates in gas pipeline (Dillion, 2003; Chen, 2004; Lu, 2005; Lu, 2008), which has already become a hot point in the field of geosciences and resources at present (Kvenvolden, 1993; He, 2005; Huang, 2007). Gao (2005) et al. monitored insitu hydrate formation and dissociation in water in black oil emulsion using NMR.
- South America > Brazil > Campos Basin (0.99)
- Asia > China > East China Sea > East China Sea Basin > Pinghu Field (0.99)
ABSTRACT For a typical field development project within the Northern Norwegian Continental Shelf, facing the North Atlantic and Barents Seas, some particular challenges are faced. These relate to the very irregular and partly soft seabed creating free spans, with trawl interaction, and maintenance of the fragile environment in general, including cold water corals. Traditional design approach has called for infill of free spans and trenching of smaller diameter flowlines to eliminate damage risk from trawl gear interaction. On very irregular seabed this may lead to excessive intervention work volumes, with associated high cost. Mitigation actions may be considered in two groups, phased in conceptual/early FEED work and detail engineering actions, respectively. The paper outlines how these challenges may be addressed during the early FEED phase to develop a field layout with focus on minimized intervention cost and risk, while fulfilling also all general layout, installation and operational requirements. Further, for the detail design phase, how new developments within fatigue and trawl design methodology is utilized to allow for significant free spans without pipe support even for clad flowline diameters of 10–12 inches. INTRODUCTION The northern Norwegian continental shelf (NCS) facing the North Atlantic and Barents Seas, is considered a very promising area for future oil and gas finds. Operating fields and ongoing development are typically located in water depths of 200–500 m, and often characterized by several smaller isolated reservoirs, with high pressure and high temperature characteristics. Wellstream composition often calls for use of corrosion resistant alloys in flowlines, examples being solid 13% Cr pipe or various clad/lined pipe options. Interesting prospects are currently investigated further out and at greater depths, down to 1200 – 1500 m. Historically, these waters have been among the most productive fish breeding areas on a global scale, with associated significant fishing industry.
- Europe > Norway > Norwegian Sea > Halten Terrace > Revefallet Fault Complex > Skarv Unit > Block 6507/6 > Skarv-Idun Field > Skarv Field > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Revefallet Fault Complex > Skarv Unit > Block 6507/6 > Skarv-Idun Field > Skarv Field > Ile Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Revefallet Fault Complex > Skarv Unit > Block 6507/6 > Skarv-Idun Field > Skarv Field > Garn Formation (0.99)
- (21 more...)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.55)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.54)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (0.48)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Offshore pipelines (0.46)
ABSTRACT The increasing diversity of worldwide pipe coating projects has challenged both suppliers and operators to maintain, and even increase quality and efficiency expectations. During this time, the need for high integrity coatings and insulation for increasingly severe installation and service conditions continues to challenge the industry. To meet these challenges, operators, mills and suppliers must continue to develop emerging technologies, while improving the quality of existing technologies. Issues such as coating of pipe produced for strain based design, thermal insulation integrity, qualification testing, and procurement issues are presented from an operator's perspective. Suggestions to improve owner supplier relationships will be discussed. INTRODUCTION Corrosion control is important to help ensure the long term integrity of a pipeline. Coatings and cathodic protection work in unison to help provide the needed corrosion protection. Coatings normally provide corrosion protection for the pipeline by providing a barrier to the corrosive external environment, soil or water. If a coating was applied with no defects or holidays and remained in that state for its design life, no additional corrosion protection would be needed. This concept also presupposes that the corrosives present in the surrounding soil or water never penetrate the coating. Experience shows that coatings do degrade and are rarely (if ever) installed defect free. Thus, the combination of coatings and cathodic protection should normally be applied to provide the needed corrosion protection. ExxonMobil Development Company uses a series of documents termed Global Practices (GPs) to help select, specify and procure pipe coatings. Generally, the GPs are the basis for the Project Specification. The GPs are normally developed by ExxonMobil Development Company but reviewed and approved by numerous Subject Matter Experts (SME's) from within the company. This paper will discuss several of the GPs as an attempt to explain the pipe coating selection process.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
The Synergism of PEG to Kinetic Hydrate Inhibitor
Chen, Li-Tao (State Key Laboratory of Heavy Oil Processing, China University of Petroleum) | Sun, Chang-Yu (State Key Laboratory of Heavy Oil Processing, China University of Petroleum) | Peng, Bao-Zi (State Key Laboratory of Heavy Oil Processing, China University of Petroleum) | Chen, Guang-Jin (State Key Laboratory of Heavy Oil Processing, China University of Petroleum)
ABSTRACT The inhibiting effect of Inhibex 301 for the CH4 + C2H6 + C3H8 gas mixtures + brine systems was assessed using a high pressure sapphire cell. The onset time of hydrate formation was determined by visual observation. The hydrate onset time of Inhibex 301 was prolonged apparently by the addition of polyethylene glycol (PEG). The subcooling of Inhibex 301 was improved dramatically after PEG was added. PEG is thought to be synergic with Inhibex 301 in the hydrate inhibition. INTRODUCTION In oil and gas industries, pipelines and production facilities might be blocked by gas hydrate, which is a kind of crystalline compounds formed by gas and water. It is well known that gas hydrate is stable at high pressure and low temperature. The temperature in offshore pipelines is usually low and the pressure is high enough to form gas hydrate. In order to reduce the risk of hydrate plug in pipelines, several methods are used (Sloan and Koh, 2008). The most popular method adopted at the present is the addition of thermodynamic inhibitors into the pipelines. The thermodynamic inhibitors could elevate the formation conditions, either lower the formation temperatures at given pressure or increase the formation pressure at given temperature. Methanol and glycols are two typical thermodynamic hydrate inhibitors which are widely used in oil and gas industries. The concentration of methanol and glycols may reach 50 wt % on the free water basis. Toxicity of methanol limits its application for environmental concerns. Moreover, the thermodynamic inhibitors are costly (Sloan and Koh, 2008). The costs make a critical burden on oil and gas industries. For the purpose of the avoidance of the costly thermodynamic hydrate inhibitors, oil and gas industry has been making variety efforts to seek new hydrate inhibitors for decades.
- Asia (0.70)
- North America > Canada (0.28)
- Europe > Norway (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)